An Introduction to Grid Services: Concepts, Technical Requirements, and Provision from Wind - Paul Denholm, Yinong Sun, and Trieu Mai - NREL
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An Introduction to Grid Services: Concepts, Technical Requirements, and Provision from Wind Paul Denholm, Yinong Sun, and Trieu Mai
Introduction
Current Grid Services
Provision of Grid Services from Wind
Conclusions and Research Needs
NREL | 2Introduction • Geographical Scope • Regions Analyzed
Geographical Scope and Regions Analyzed
Market Regions Estimated Estimated
Electric Population
Demand (TWh / (million / % of
% of U.S.) Total)
CAISO 228 / 6% 30 / 9%
PJM 759 / 19% 65 / 20%
ERCOT 357 / 9% 23 / 7%
ISO-NE 121 / 3% 14.5 / 4%
NYISO 157 / 4% 19.5 / 6%
MISO 656 / 16% 48 / 15%
SPP 246 / 6% 18 / 6%
Regulated Regions
Non-CAISO WECC 654 / 16% 52 / 16%
FRCC 231 / 6% 16 / 5%
SERC 673 / 16% 39.4 /12%
NREL | 4Current Grid Services • Energy and Capacity • Operating Reserves • Other Essential Reliability Services • Relative Total System Costs
Current Grid Services
Category of Timescale
• We separate energy and Service mS S Min Hr Day Month Year
capacity services into one Energy and Energy
category and group the Capacity Firm Capacity
remaining services into a Frequency Responsive Reserves
general essential reliability
Essential Reliability
Regulating Reserves
Operating
Reserves
service (ERS) category. Contingency Reserves
• ERSs are further Services Ramping Reserves
subdivided into operating Other
Voltage Support
reserves and other ERSs. Black-Start Capability
mS S Min Hr Day Month Year
NREL | 6Historical Capacity Requirements
U.S. Power System Historical Peak and Annual Energy Demand
Region Peak Demand (GW)
2016 2017
CAISO 46.2a 50.1a
PJM 152.2c 145.6c
ERCOT 71.1e 69.5e
ISO-NE 25.6g 24.0g
NYISO 32.1i 29.7i
MISO 121.0k 120.6k
SPP 50.6m 51.2m
Non-CAISO WECC 110.8o 106.0o
FRCC 47.7q 46.6q
SERC 129.0s 132.2s
Totalt 786 775
Each region is required to maintain sufficient capacity to meet the peak demand plus
additional capacity to address outages or unanticipated increases in demand.
NREL | 72020 Estimated Regional Capacity Requirements
U.S. Power System Peak Capacity Requirement Estimates
Region 2020 Estimated NERC Estimated 2020 Estimated Total 2020 Estimated
Peak Demand Reference Margin Peak Capacity Reserve Margin
(GW)a Level (%)b Requirement (GW) (%)
Market Regions
CAISO 53.6 16.14 62.3 20.6
PJM 147.5 16.60 172.0 28.0
ERCOT 73.7 13.75 83.5 18.0
ISO-NE 26.3 16.90 30.3 23.8
NYISO 32.1 15.00 36.9 25.0
MISO 121.4 15.80 140.6 19.4
SPP 52.5 12.00 58.8 28.9
Regulated Regions
Non-CAISO 23.7 (range of
110.0 range of 14.17 to 16.38 136.0
WECC 22.6 to 27.7)
FRCC 45.8 15.00 52.7 22.5
SERC 131.2 15.00 150.9 23.1
All U.S. regions are expected to have adequate generation capacity
to meet peak demand in the near future.
NREL | 8Energy Capacity Costs and Prices
• Most costs associated with power system generation are the fixed and
variable costs associated with providing capacity and energy.
• Price caps and other factors typically require additional costs of capacity
(i.e., “missing money”) to be captured via other mechanisms, including
resource adequacy payments and/or capacity markets.
• Most U.S. regions have more capacity than is needed for resource
adequacy/planning reserve targets, which tends to suppress capacity
market prices.
NREL | 9Energy Capacity Costs and Prices
U.S. Power System Energy Requirements
Region Average Energy Price ($/MWh) Capacity Market Price ($/kW-month)a
2016 2017 16/17 17/18
Market Regions
CAISO $33.1b $33.3b N/A
PJM $29.68c $30.85c $1.81c $3.66c
ERCOT $24.62d $28.25d NA
ISO-NE $31.74e $35.23e $3.15e $7.03e
$31.32f $34.62f Summer: $1.73g Summer: $1.25g
NYISO Winter: $5.77g Winter: $6.49g
MISO $26.80h $29.46h NA
SPP $22.43i $23.43i NA
NREL | 10Operating Reserves
Defined as the capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages, and local
area protection.
Distinctions can be
characterized by three factors:
• How much
• How fast
• How long
There are no uniform definitions
for various operating reserve products.
NREL | 11Timescales of Operating Reserve Requirements
Timescale
mS S Option
Min 3 Hr Day
Inertial Response
1. Frequency
Responsive Primary Frequency Response Services
Reserves currently
Fast Frequency Response not
procured
2. Regulating via markets
Regulating Reserves
Reserves
Proposed
Spinning Reserves or early
3. Contingency adoption
Non-spinning Reserves market
Reserves
services
Replacement Reserves
Currently
4. Ramping Ramping Reserves procured
Reserves via markets
5. Normal operation
provided by “energy Economic Dispatch
and capacity”
mS S Min Hr Day
NREL | 12Operating Reserves
Resources with different technical characteristics are deployed at different times;
typically, they are deployed in order of response speed, from very fast to slow (and
with corresponding costs that range from more to less expensive).
Frequency-Responsive Reserves
• Inertial Response
• Primary Frequency Response
• Fast Frequency Response
Regulating Reserves
During normal operation, reserves are still required to meet random variations
in net load
NREL | 13Operating Reserves
Contingency Reserves
• Spinning Reserves
• Non-Spinning/Supplemental Reserves
Ramping Reserves
• Least well defined of the reserve products
• Not yet a common market product
Economic Dispatch (Normal System Operation)
All reserves are eventually replaced by the normal economic dispatch of conventional
generators as the system is restored to a pre-contingency state. This is not considered
an operating reserve or ERS and is provided by generators delivering energy and
capacity services.
NREL | 14Frequency-Responsive Reserve Requirements
Frequency-responsive reserves traditionally consist of two services:
• Inertial response
• PFR
• Neither inertial response nor PFR is a market product in any ISO/RTO market
Inertial Response
• Not much detailed estimation of inertial response requirements in U.S.
• Growing analysis of potential need to procure inertial response services
• Only ERCOT has studied the amount of inertia potentially “required”
• Requirement is measured in energy—how much energy can be injected
rapidly into the system
• Often measured in GW-seconds
• No “headroom” component of inertial response
• The amount of inertia that can be provided by a generator is independent
of instantaneous power output NREL | 15Frequency-Responsive Reserve Requirements
Primary Frequency Response Obligation
PFR Interconnection Region IFRO
(MW/0.1Hz)a
MDF (Hz)b Requirement (MW / %
of Peak Demand)
• NERC has ERCOT ERCOT 381 0.405 1,543 / 2.2%
Western Western Total 858 0.28 2,402 / 1.5%
established CAISO 196.5 550 / 1.1%
minimum Non-CAISO 661.5 1,852 / 1.7%
Eastern Eastern Total 1015 0.42 4,263 / 0.8%c
recommended FRCC 76.2 320 / 0.7%
standards for PFR SERC 303.6 1,275 / 1.0%
NYISO 49.9 210 / 0.7%
for each of the PJM 258.3 1,085 / 0.7%
three U.S. grids ISO-NE 38.3 161 / 0.7%
MISO 210 882 / 0.7%
• Each interconnection has a frequency response obligation
• Further divided by BA in proportion to demand so that each region
“shares” its obligation
NREL | 16Regulating Reserve Requirements and Costs
• Regulating reserves are a market product in each ISO/RTO
• Most technically demanding requirements of the various reserve
products in terms of response rate and the need for nearly continual
ramping of the plant providing this service
• Typically the most costly of the reserve services
NREL | 17Regulating Reserve Requirements and Costs
Market Regions Average Regulation Requirement (% of Peak 2017 Average Price ($/MW-hr)
Regulating Reserve Requirements Demand / MW)
Regulation Up: 0.64% / 320 Regulation Up: $12.13
For the requirement in CAISO
Regulation Down: 0.72% / 360a Regulation Down: $7.69b
Off-peak: 0.36% / 525
non-market regions, we PJM
On-peak: 0.55% / 800c
$16.78d
multiply the percentage ERCOT
Regulation Up: 0.48% / 318 Regulation Up: $8.76
Regulation Down: 0.42% / 295e Regulation Down: $7.48f
requirement of a large ISO-NE
NYISO
0.25% / 60g
0.73% / 217i
$29.23h
$10.28j
utility in that region by the MISO 0.35% 425k
Regulation Up: 0.92% / 470 Regulation Down:
$9.74l
Regulation Up: $8.20
total peak demand of the SPP
0.63% / 325m
(% of Peak Demand / Estimated Region
Regulation Down: $6.60n
larger region in which it is Regulated Regionso
Non-CAISO WECC
Requirement in MW)
Tariff ($/kW-month / $/MW-hr)
located (proxy utility: Arizona Public 1.17% / 1,240p $7.41/$10.29
Service)
FRCC
(proxy utility: Florida Power & 1.35% / 629q $4.8/$6.67
Light)
SERC
(proxy utility: Southern 1.15% / 1,477r $4.2/$5.83
Company)
National (% of Total)s / Estimated Total Requirement Average Price ($/MW-hr)t
0.90% / 6,000 MW $11.24
NREL | 18Contingency Reserve Requirements and Costs
Spinning Contingency Reserve Requirements
Market Regions Spinning Requirement (% of Peak 2017 Average Price ($/MW-hr)
The actual quantity Demand / MW)
CAISO 1.60% / 800 MWa $10.13b
procured is typically PJM 1.03% / 1,504.8 MWc $3.73d
greater than ERCOT
ISO-NE
3.76% / 2,616.8 MWe
3.75% / 900 MWg
$9.77f
$2.96h
regulation NYISO
MISO
2.20% / 655 MWi
0.61% / 740 MWk
$5.00j
$2.94l
requirements, but SPP 1.14% / 585 MWm $5.25n
(% of Peak Demand) / Estimated
the price is typically Regulated Regions
Region Requirement
Tariff ($/kW-month / $/MW-hr)
Non-CAISO WECC
lower due to the 1.50% / 1590 $6.26 / $8.69
(Arizona Public Service)
infrequent ramping FRCC
0.43% / 200 $5.16 / $7.17
requirements. (Florida Power & Light)
SERC
2.00% / 2,568 $4.2 / $5.83
(Southern Company)
National (% of Total)o / Estimated Total Average Price ($/MW-hr)p
Requirement
1.58% / 12,160 $6.15
NREL | 19Contingency Reserve Requirements and Costs
Non-Spinning Contingency Reserve Requirements
Market Regions Non-Spinning Requirement (% of Peak Demand / 2017 Average Price ($/MW-hr)
The procurement CAISO
MW)
1.60% / 800 MWa $3.09b
requirement (total MW) PJM
ERCOT
1.03% / 1,053.2 MWc
2.21% / 1,534.5 MWe
$2.11d
$3.18f
10-minute total reserve: 5.98% / 1435 MW 10-minute non-spinning reserve: $0.89
for non-spinning reserves ISO-NE 30-minute operating reserve: 3.33% / 800 MWg 30-minute operating reserve: $0.82h
is typically similar to that
of spinning reserves
10-minute total reserve: 4.41% / 1310 MW 10-minute non-spinning: $4.18
NYISO 30-minute reserve: 8.82% / 2620 MWi 30-minute component: $4.01j
(because non-spinning MISO 0.92% / 1,110 MWk $1.14l
typically replace spinning). SPP 1.43% / 730 MWmRamping Reserve Requirements
Ramping (Flexibility) Requirements by Region
Region Requirement
• Maximum flexible ramp up and down requirements are defined as the 2.5% and the 97.5% percentile of net load change
• Uncertainty threshold:
o For the system in the 15-minute market: -1,200 MW in the downward direction and 1,800 MW in the upward
CAISO direction;
o For the system in the 5-minute market: -300 MW and 500 MW in the downward and upward directiona
• Depends on the sum of the forecasted change in net load and an additional amount of ramp up/down (575 MW for now)
• Highest hourly average real-time ramp-up requirement: 1,554 MW
MISO
• Highest hourly average real-time ramp-down requirement: 1,614 MWb
These reserves are an emerging product with limited market data for analysis.
NREL | 21Total Reserve Requirements
8,000 14%
7,000
Fraction of Annual Peak Demand
12% Ramping
Capacity Needed (MW)
6,000 Nonspinning
10%
5,000
8% Spinning
4,000
6% Regulation
3,000
PFR
4%
2,000
Pct Peak Energy
1,000 2% Demand
0 0%
NREL | 22Total Energy and Reserve Requirements
160
140
Capacity Needed (GW)
120
100 Ramping
80 Nonspinning
Spinning
60
Regulation
40
PFR
20
Energy
0
NREL | 23Other Essential Reliability Services
• There are a number of other ERSs; two of the most important are:
• Black-start
• Voltage support
• A significant difference from other services is that these are typically
acquired on a cost-of-service basis
NREL | 24Black-Start
• Represents capacity that can be started without external power and then
subsequently provide power and energy to start other power plants
• Typically relatively small power plants including certain hydroelectric
facilities, diesel generators, or small gas turbines
• Historically been procured on a cost-of-service basis, even in wholesale
market regions
• Each region has specific technical requirements for the type and
quantity procured
NREL | 25Voltage Support
• Ensuring electric system reliability requires maintaining both frequency and voltage
• Frequency is constant throughout the grid.
• Voltage varies depending on location.
• Devices that provide voltage control maintain appropriate voltage on the grid
during both normal operating conditions and fault conditions.
• Voltage is controlled by different methods at different points of the grid.
• Key element of this is the ability to inject or absorb reactive power.
• Reactive power cannot be transmitted over long distances.
• Voltage control is performed at each of the three major parts of the grid,
including at the point of generation, at various points in the transmission
system, and in the distribution network. For additional discussion of reactive
power.
• Reactive power is provided by “active” devices such as synchronous generators or
power electronics devices or by “passive” devices such as capacitor banks.
NREL | 26Relative Total System Costs
• Vast majority of generation-related costs are associated with the provision of
energy and capacity
2017 PJM Market Settlements Summaryb
2017 ISO-NE Market Settlements Summarya
Billing
Billing ($ Million) Percentage
($ Million) Percentage Energy market 21,087 52.49%
Energy markets total 4,522 49.50% Capacity 9,103 22.66%
Forward capacity market payments 2,244 24.56% Transmissionc 8,739 21.75%
Regional network service 2,163 23.68% Scheduling 366 0.91%
Reserve markets total 70 0.77% Reactive services 309 0.77%
Net commitment-period compensation 52 0.57% Regulation market 104 0.26%
Regulation market 32 0.35% Black-start 72 0.18%
Financial transmission rights (FTRs) 20 0.22% Operating reserves 68 0.17%
Black-start 12 0.13% Synchronized reserve market 49 0.12%
Volt-ampere-reactive capacity cost 20 0.22% Day-ahead scheduling reserve market 34 0.08%
Demand-response payments 1 0.01% Other 241 0.60%
Total $9,136 100.00% Total $40,172 100.00%
NREL | 27Provision of Grid Services from Wind • Energy and Capacity • Operating Reserves • Other Essential Reliability Services
Provision of Services from Wind
More than 1,000 MW of wind generation capacity has been deployed in each of
the regions analyzed, with the exception of SERC and FRCC.
2017 Wind Energy Provision
The value of the energy
and capacity provided by Region Installed Capacity (MW) Annual Energy (GWh) Fraction of Demand
(%)
wind is impacted by the Market Regions
variable nature of the CAISO
PJM
6,296
8,141
12,823
20,714
6.0
2.7
resource. ERCOT
ISO-NE
21,704
1,401
62,193
3,444
17.4
2.6
Wind tends to be NYISO 1,826 4136 2.7
MISO 17,000 50,535 7.7
somewhat negatively SPP 17,591 58,874 23.2
correlated with demand Regulated Regions
Non-CAISO WECC 16,766 43,967 6.7
patterns over the diurnal FRCC 0 0 0
SERC 237 514 0
and seasonal cycle. Total 87,331 225,585 5.5
NREL | 29Energy and Capacity
• Most ISO/RTOs and large utilities with substantial wind deployments have
performed capacity credit analysis of wind.
• The following table demonstrates that for nearly all regions of the United
States, a capacity credit of significantly less than 50% is applied to wind,
with capacity credits well under 20% applied in many cases.
NREL | 30Energy and Capacity
Capacity Credit by Market Region
Region Capacity Credit
Market Regions
CAISOa Summer values of about 27%.
Initially applies 13% of nameplate; after three years of operation, historic performance over seasonal peak periods determine unit’s capacity
PJMb
credit.
Based on average historical availability during the highest 20 seasonal peak load hours for each season (2009–2016). Values recalculated after
ERCOTb each season with new historical data. Current contribution: 58% coastal and 14% noncoastal (summer); 35% coastal and 20% noncoastal
(winter).
ISO-NEb Summer values average to approximately 13.2% of nameplate rating.
Onshore: summer 10%; winter 30%
NYISOc
Offshore: 38%
MISOd
2016 15.6%
2017 15.6%
2018 15.2%
5% assumed for first three years if the load-serving entity (LSE) chooses not to perform the net capability calculation during the first 3 years of
SPP operation, after which the net capability calculations are applied by selecting the appropriate monthly MW values corresponding to the LSE’s
peak load month for each season.
Regulated Regions
Varies. For example, Xcel Colorado uses 16%.e Portland General Electric uses 5%–15% for wind resources located in the Pacific Northwest.f
Non-CAISO WECC
FRCC Not applicable.
SERC Varies.
NREL | 31Operating Reserves
• Wind was once considered a non-dispatchable “must-take” resource without the
ability to provide reserves
• Now recognized that the output of a wind turbine can be accurately controlled (up
to the amount allowed by instantaneous wind speed)
• Wind has important differences that provide both relative advantages and
disadvantages compared to more traditional resources.
Key Parameters for Provision of Operating Reserves for Thermal/Hydro Resources and Wind
Parameter Thermal/Hydro Wind
Dispatch Range Min to max, min is typically 25% to 50% of 0 to max, where maximum output is
(“how much”) maxa variable (limited by current wind speed)
Ramp Rate (“how Start time ranges from several minutes to Ramp rate greater than 5%/secondc
fast”) hours. Ramp rate when online ranges
from about 1%/min for combined-
cycle/coal to 5%/min for combustion
turbine
Availability of Typically unconstrained with fuel Contingent on wind resource, which has
Output (“how availability increased unpredictability with duration
long”)
NREL | 32Operating Reserves
• Wind performance is different from that of conventional generators
• Technical ability of wind to provide reserves varies by service
• Key element of providing reserves from wind is the need for pre-curtailment, which
incurs the opportunity cost of reduced energy sales
• Pre-curtailment requires reducing the output of the wind turbine, performed
by changing the blade pitch angle and reducing the amount of energy
extracted from the wind
• Pre-curtailment requirement reduces the revenue from electricity sales for a
wind generator providing this service, at least under current market conditions
• Wind generators will always prefer to provide energy instead of reserves as long as
the price of energy is greater than the price of reserves.
NREL | 33Operating Reserves
• As variable generation penetration increases, there may be times when the price of
energy falls to zero and wind is curtailed.
• Under certain conditions, it may be economically advantageous—for the wind plant
and the system—for curtailed wind to provide reserves and wind can potentially
improve overall system dispatch by allowing decommitment (turning off) of more
costly (on an operating basis) generators that are online primarily to provide
reserves.
• Most wind curtailment has been due to transmission constraints, where wind
would not be able to provide reserves, as the location where reserves are needed
does not correspond to the location of the wind.
NREL | 34Operating Reserves
While the need for pre-curtailment is an economic factor, an important technical
factor is ensuring that headroom will remain available for the response time needed.
Impact of variable output on the ability of wind to provide upward reserve services
NREL | 35Operating Reserves
• Wind can increase output very rapidly, but the duration of response becomes
problematic.
• The “how long” component of reserve service from wind is limited by both the
likelihood of wind remaining at or higher than current output and the predictability
of this output.
• While the forecast accuracy of wind is increasing, the ultimate limit to wind
headroom is the relatively low capacity credit.
• A system operator may not be able to plan on the availability of wind to provide
upward reserves, and insufficient wind during certain periods may require other
sources of capacity to be available to provide reserves.
• Wind will act to reduce the variable costs associated with providing reserves, but
have somewhat limited availability to reduce the fixed costs.
NREL | 36Frequency-Responsive Reserves
• Wind generators have demonstrated the ability to provide both an “inertia-like”
product and PFR, and FERC requires new wind turbines to provide PFR.
• Modern wind turbines do not use synchronous generators
• Do not provide inertia in the traditional sense (defined as automatically
resisting changes in frequency)
• Have kinetic energy in the rotating mass of the blades, shaft, and generator
that can be extracted to rapidly inject real power into the grid
• Provision of inertial service in this fashion requires active sensing of grid frequency.
• When a decrease in frequency is sensed, the generator can be programmed to
increase output to beyond what can be supported by “steady state” wind
speeds.
NREL | 37Frequency-Responsive Reserves
• The provision of inertia from wind turbines in this manner is unique
compared to other reserve service provisions in that it does not require
pre-curtailment of wind.
• Sometimes been referred to as “synthetic” inertia
• Combination of extracting energy from rotating wind turbines and using
pre-curtailed wind energy to provide a rapid increase in output can mimic
traditional frequency-responsive reserves
• These services do not precisely match those from conventional
generators.
• Terminology is still in flux.
NREL | 38Frequency-Responsive Reserves
• “Fast frequency response” (FFR) has emerged as a preferred term that
captures the ability of non-synchronous generators to inject real power
into a grid upon sensing a change in frequency.
• Difference between FFR and PFR is less clear; generally PFR would reflect a
somewhat slower response (but still measured in a few seconds or less)
• Still important to distinguish frequency response that is derived from
extraction of turbine kinetic energy as opposed to from pre-curtailment,
given the potentially economic implication of these different sources
Terms Applied to Frequency-Responsive Services
Conventional Synchronous Generator Wind (Previous Terms) Wind (Current Terms)
Inertia Synthetic inertia (derived FFR (derived from kinetic
from kinetic energy) energy)
PFR PFR from pre-curtailment PFR or FFR (from pre-
curtailment)
NREL | 39Frequency-Responsive Reserves
• Ability of wind to provide frequency response from both extraction of kinetic
energy and increased output from pre-curtailed wind is well established
• Major wind turbine manufacturers offer this service.
• ERCOT requires all new turbines to have FFR capabilities.
• Manner in which wind can provide frequency-responsive services is also
evolving
• Can be “programmed” to provide a response similar to that of legacy
synchronous generators
• It is possible wind response can be optimized to grid requirements and
vary based on both the current frequency and the rate of change of
frequency (ROCOF).
NREL | 40Regulating Reserves
• Require synchronized generator to have the ability to increase or decrease
output in response to a signal from the system operator
• Wind requires pre-curtailment to provide upward reserves
• There has been limited use of wind to provide regulating reserves,
with one example being Xcel Energy in Colorado.
• Regulating reserves are typically the highest-cost reserve product
• Rules for wind providing regulating reserves are unclear, inconsistent, and
evolving in U.S. ISO/RTO markets
NREL | 41Ramping Reserves
• Similar to regulating reserves in that they require a generator to have the
ability to increase or decrease output in response to a dispatch signal.
• Primary difference is that flexibility reserves are generally slower (i.e.,
lower ramp rate) and longer (i.e., requiring the generator to hold
output for a longer period)
• Makes this reserve product easier to meet for a conventional
generator, and a lower-cost service from the system perspective
• A flexibility reserve product is likely to have lower costs than regulation.
NREL | 42Contingency Reserves
Spinning Contingency Reserves
• Must have the ability to:
1. Be synchronized to the grid and begin responding quickly (within a few
seconds)
2. Reach setpoint within about 10 minutes
3. Hold output for at least 30 minutes (60 in a few locations)
• For pre-curtailed wind, criteria 1 and 2 are well within the technical requirements.
• Third requirement could be more challenging given the greater variability and
lower predictability of wind over longer timescales
• Contingency reserve prices are typically lower than those of regulation.
• Little incentive for wind to provide this service, and market rules have limited
explicit discussion of wind providing it
NREL | 43Contingency Reserves
Non-spinning Contingency Reserves
• Upward-only reserve product that can be provided by online generators, or units
that can start quickly
• Non-spinning reserves typically the lowest-cost operating reserve service
• Long-duration requirement (multiple hours) may limit the ability of wind to provide
this service given the constraints of predictability and limited capacity credit
NREL | 44Other Essential Reliability Services
Voltage Support
• Power electronics built into wind turbines are well suited to providing voltage
control and reactive power.
• Variable generation power plants larger than 20 MW must provide reactive power
• Aggregated capacity of the plant, which typically consists of multiple turbines
or solar arrays
• Modern wind turbines can also provide reactive power even when not generating.
• Voltage support is a localized service, and grids often need it in areas where it is not
possible to place wind turbines.
NREL | 45Other Essential Reliability Services
Black-Start Capacity
• Must be able to start on its own without grid power and create a reference grid
frequency
• Provides other generators with sufficient power to energize station power
requirements, start, and synchronize
• Wind turbines typically start using external grid power.
• Parasitic/operating loads are relatively small and could be provided using a battery
or small auxiliary generator.
• Some have “grid-forming” capacity, or the capability to create an AC reference.
• Primary challenge of black-start capability from wind turbines is their low capacity
credit and variability.
• There has been very little analysis of the ability of wind to provide black-start
capability in the United States.
NREL | 46Summary – Grid Services from Wind
• Both existing practices and ongoing research indicate that wind can
technically provide nearly all services procured and utilized in the grid, but
this ability is constrained by the geographical and temporal availability of
the wind resource.
• Wind does not provide all services in U.S. regions currently due to market
rules, the aforementioned constraints, and economic considerations.
• Until there is significant curtailment of wind energy, wind will likely
continue to act primarily as an energy resource.
NREL | 47Summary – Grid Services from Wind
Service Market Procured Wind Can Wind Currently Requires Pre-
and Compensated Technically Provides in U.S.? Curtailment for Wind to
Service? Provide?a Provide?
Capacity Y Y Y N
Energy Y Y Y N
Inertial Response N Y N/A Nob
Required but not
Primary Frequency compensated –
Response proposals only Y Limited Y
Fast Frequency
Response N – proposals only Y Limited Y
Regulating
Reserves Y Y Limited Y
Contingency –
Spinning Y Y Limited Y
Contingency – Non-
spinning Y Y No Y
Contingency –
Replacement Y Maybe No Y
Ramping Reserves Y (some locations) Y Limited Y
Yc – location
Voltage Support Y – cost of Service dependent Limited N
Unclear, location
Black-Start Y – cost of Service dependent No N NREL | 48Conclusions and Research Needs
Conclusions
• There is potential for growth in and changes to essential reliability service requirements—and
potential for wind energy to provide them.
• Wind has already demonstrated the capability to provide multiple reserve services, with
response rates that meet or exceed those from conventional synchronous generators.
• Major limitation in providing operating reserves is the need to pre-curtail and provide upward
headroom
• Reduces the amount of energy that can be sold
• Little economic incentive to provide these services in today’s grid
• As curtailment increases due to greater wind deployment, or as reserve requirements
increase, it may become more economic for wind to provide reserves.
• Wind is far more suited for shorter-term (but more valuable) services that can take advantage
of wind’s rapid response rate, including FFR, PFR, and regulating reserves.
NREL | 50Research Needs
• Further analysis is needed to determine both the types and quantities of reserves
needed to address greater variability and uncertainty of net load under future grid
conditions.
• Important consideration is the evolution of energy markets under these future
conditions.
• A variety of technologies including wind can provide services needed by the grid,
but market products may need to be altered to align the technical needs with
appropriate economic incentives.
NREL | 51Read the full report:
https://www.nrel.gov/docs/fy19osti/72578.pdf
www.nrel.gov
NREL/PR-6A20-73590
This work was authored by the National Renewable Energy Laboratory, operated by Alliance for Sustainable Energy, LLC,
for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding provided by the U.S.
Department of Energy Office of Energy Efficiency and Renewable Energy Wind Technologies Office. The views expressed
in the article do not necessarily represent the views of the DOE or the U.S. Government. The U.S. Government retains
and the publisher, by accepting the article for publication, acknowledges that the U.S. Government retains a
nonexclusive, paid-up, irrevocable, worldwide license to publish or reproduce the published form of this work, or allow
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